1. Field of the Invention
The invention relates generally to earth-boring bits used to drill a borehole for the ultimate recovery of oil, gas or minerals. More particularly, the invention relates to rolling cone rock bits with improved hydraulics and vectored nozzle retention sleeves.
2. Background of the Invention
An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. The borehole thus created will have a diameter generally equal to the diameter or “gage” of the drill bit.
An earth-boring bit in common use today is a rock bit including one or more rotatable cutters that perform their cutting function due to the rolling movement of the cutters acting against the formation material. The cutters roll and slide upon the bottom of the borehole as the bit is rotated, the cutters thereby engaging and disintegrating the formation material in its path. The rotatable cutters may be described as generally conical in shape and are therefore sometimes referred to as rolling cones or rolling cone cutters. The borehole is formed as the action of the rotary cones remove chips of formation material.
The earth disintegrating action of the rolling cone cutters is enhanced by providing a plurality of cutting elements on the cutters. Cutting elements are generally of two types: inserts formed of a very hard material, such as tungsten carbide, that are press fit into undersized apertures in the cone surface; or teeth that are milled, cast or otherwise integrally formed from the material of the rolling cone. Bits having tungsten carbide inserts are typically referred to as “TCI” bits or “insert” bits, while those having teeth formed from the cone material are known as “steel tooth bits.” In each instance, the cutting elements on the rotating cutters break up the formation to form the new borehole by a combination of gouging and scraping or chipping and crushing.
During drilling operations drilling mud or fluid is pumped to the drill bit through the drillstring, and is ejected from the face of the drill bit through a series of jets or nozzles. The rock fragments and formation cuttings between the cutting elements and along the borehole bottom are flushed away and carried to the surface in the annulus formed between the drill string and borehole by drilling mud or fluid. In particular, the drilling fluid impacts and flows past the cutting structure, and carries the cuttings radially outward on the borehole bottom, and then upward through the annulus to the surface.
In oil and gas drilling, the cost of drilling a borehole is very high, and is proportional to the length of time it takes to drill to the desired depth and location. The time required to drill the well, in turn, is greatly affected by the number of times the drill bit must be changed before reaching the targeted formation. This is the case because each time the bit is changed, the entire string of drill pipe, which may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. As is thus obvious, this process, known as a “trip” of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to employ drill bits which will drill faster and longer, and which are usable over a wider range of formation hardness.
The length of time that a drill bit may be employed before it must be changed depends upon its rate of penetration (“ROP”), as well as its durability. One design element that significantly affects bit ROP and durability is the hydraulics—the design and layout of the jets and nozzles in the bit face, and the direction and energy of the flow of drilling fluid. For example, when drilling softer formations and plastic formations, there is a strong tendency for formation cuttings to adhere rolling cones and between the cutting elements, a phenomena commonly referred to as “bit balling”. When bit balling occurs, the penetration of the individual cutting elements into the formation is limited by the cuttings and fragments stuck to the cones, thereby reducing the amount of formation material removed by the cutting elements and associated reduction in rate of penetration (ROP). In harder clays and shales, cuttings can become impacted or “balled up” between the cutting elements. When formation sticks to cones or is impacted between cutting elements it limits cutting element penetration. Also, formation packed against the cone-shell closes the flow channels needed to carry other cuttings away. This may promote premature bit wear. In either instance, having sufficient fluid directed toward the cones can help to clean the inserts and cones, allowing them to penetrate to a greater depth, maintaining the rate of penetration for the bit. Furthermore, as the inserts begin to wear down, the bit can drill longer since the cleaned inserts will continue to penetrate the formation even in their reduced state. Thus, cuttings must be removed efficiently during drilling to maintain reasonable penetration rates.
Some conventional nozzle arrangements include the placement of a nozzle between each of the cones proximal the outer periphery of the bit or at the center of the bit to channel fluid flow directly to the borehole bottom. However, these arrangements are not desired in many applications where bit balling is a concern because they may not provide sufficient cleaning of the interior rows of cutting elements. In other conventional designs, additional nozzles are positioned over each of the cones which direct a jet stream of fluid directly on top of the cones. The problem with these designs is that the impact of fluid directly on top of the cones may result in severe erosion on the cones and a premature loss of cutting elements from the cone.
Hydraulic optimization in relatively larger bits may be particularly challenging. For example, the greater the hydraulic energy of the drilling fluid, the greater its ability to impact and dislodge formation cuttings from the cutting elements and cones. However, due to diffusion, the hydraulic energy of drilling fluid exiting the bit face generally decreases with distance from the nozzle. For smaller bits, the distance from the exiting nozzle to the cone and cutting elements may be relatively small, and thus, hydraulic energy loss may be minimal. However, for relatively larger bits, the distance traveled by the drilling fluid exiting the nozzles before impacting the cones and cutting elements may be large, resulting in significant hydraulic energy loss and a reduced ability to flush formation cutting. Moreover, for relatively larger bits, the surface area of the cutting structure and the borehole bottom to be cleaned is increased.
In general, modifications to bit hydraulics have generally been difficult to accomplish due to manufacturing and geometric limitations. Usually, bits are constructed using one to three legs that are machined from a forged component. This forged component, called a leg forging, has a predetermined internal fluid cavity or plenum that directs the drilling fluid from the center of the bit to the peripheral jet and nozzle bores. A receptacle for an erosion resistant nozzle is machined into the leg forging, as well as a passageway that is in communication with the internal plenum of the bit. Typically, there is limited flexibility to move the nozzle receptacle location or to change the center line direction of the nozzle receptacle because of the geometrical constraints for the leg forging design.
It may be possible to modify the leg forging design to allow the nozzle receptacle to be machined in different locations depending on the desired flow pattern and hydraulic layout. However, due to the cost of making new forging dies and the expense of inventorying multiple forgings for a single size bit, it may not be cost effective to frequently change the forging to meet the changing needs of the hydraulic designer.
Accordingly, there is a need for bits having an improved bit hydraulics that provide vectored and targeted cleaning for cutting elements along the outer and inner rows of the cones to minimize bit balling without directly impinging the cone shell leading to erosion on the cones. Such improved hydraulics would be particularly well received if they also provided a cost effective and flexible design methodology to optimize hydraulics in the field for specific applications.